Most wells are drilled today utilizing a string of drill pipe. The drill pipe is made up of joints of pipe that are secured together by threads. The drill pipe is rotated either by a kelly bushing of the drilling rig or by a top drive of the drilling rig. Also, particularly in deviated wells, the operator may mount a drill or mud motor in the drill string just above the drill bit. The drill motor has a stator and a rotor, and drilling fluid pumped down the drill string causes the rotor to rotate the drill bit. While operating the drill motor, the operator may continue to rotate the drill string or may allow the drill string to remain stationary from time to time for steering the drill bit in a desired direction. At various depths and after the well is completed, the operator retrieves the drill string and runs casing into the well. The operator cements the casing in place.
Another type of drilling utilizes a casing string or a liner string as the drill string rather than a separate section of drill pipe. Casing and liner comprise pipes that are intended to be cemented in the wellbore to line the wellbore. A difference between casing and liner is that each string of casing installed will extend back to the wellhead; the upper end of a liner string normally extends up only a short distance past the lower end of the last string of casing installed in the wellbore. For the purposes herein, both casing and liner will be referred to as casing. Casing is larger in outer diameter and inner diameter than conventional drill pipe.
Typically, a bottom hole assembly latches to the lower end of the string of casing. When the casing has drilled to a desired depth, the operator may retrieve the bottom hole assembly from the casing and cement the string of casing in place. An operator may also utilize a drill motor mounted in the bottom hole assembly for rotating the drill bit relative to the bottom hole assembly and the string of casing.
Drill motors are used for a variety of reasons while drilling with casing. They may be used in a “steerable” configuration for drilling along a non-vertical trajectory. They may be used in a straight-hole configuration for minimizing casing wear or reducing casing vibrations by allowing the casing to be rotated at a slow speed while rotating the drilling assembly at a higher speed. Drill motors may also be used to improve the penetration rate by providing higher bit rotational speed than would otherwise be practical.
There are generally two types of drill motors, one being a positive displacement motor and the other a turbine. The positive displacement motor has an elastomeric stator with a central passage having a helical contour. A rotor, normally formed of metal, extends through the passage. The rotor has a helical contour containing a different number of lobes from the stator. The discussions herein deal only with the positive displacement motor and are not applicable to turbine drill motors.
Drill motors provide a linear output torque proportional to the pressure drop through the power section of the motor. The bit speed is typically proportional to the flow rate of drilling mud passing through the motor. However, there is a slight decrease in rotational speed as the drill motor is loaded at higher torques and drilling fluid bypasses between the rotor and stator. Drill motors can be designed to provide a wide range of performance characteristics by selecting the diameter of the power section, the power section lobe configuration, the number of stages and the pitch of the stages.
In general, the end user is faced with a choice of selecting the proper motor from a catalogue of many motors provided by a number of motor providers. These drill motors are usually described along with a power curve, which is a graph of the output torque versus the internal fluid pressure drop as the fluid passes through the motor. Two main parameters other than motor size are used to characterize a motor. One is the maximum torque that can be provided, and the other is the rotational speed, which may be defined in terms of rotations per gallon of fluid throughput. The end user first selects the group of motors defined by the appropriate, usually largest, diameter that will fit in the hole to be drilled. Next, the flow rate of the drilling fluid is selected to provide adequate transport of the cuttings back up the annulus around the drill pipe while allowing the pressure losses in the wellbore annulus to be limited for well control and bore hole stability. A group of motors is then identified that provides the appropriate rotational speed for the drilling tools that will be used in the well. Finally, a motor is selected from this group that has sufficient torque to turn the drilling tools at the maximum weight on the bit expected to be needed to drill the well.
When drilling with casing, the process of selecting a drill motor described above often does not lead the user to a selection that will power the drilling equipment effectively. The central bore of the casing drill string is much larger than the central bore or a drill pipe drill string, which includes drill pipe and drill collars. Selecting the drill motor as if one would select a drill motor for a drill pipe drill string can lead to motors that may do not drill efficiently.